Hydraulic fracturing has been an essential part of the gas development program in Saudi Arabia. In particular, proppant fracturing treatments have increasingly grown in number in recent years, which provided an incentive to look for viable alternatives to imported proppants. A new hydraulic fracturing design that utilized local sand as nonstandard proppants was recently applied in gas wells producing from sandstone formations in Saudi Arabia. This paper presents the theory behind the new fracturing design and summarizes the main results and recommendations. Sand quality-control lab tests were required prior to using Saudi Arabian sand as a propping agent in fracturing gas wells. The sand samples were analyzed for particle sizes, bulk densities, and compressive strengths. Well selection to apply the fracturing stimulation was then made based on a geomechanical criterion for the reservoir rock and the well's production performance. The treatment design utilized a channel-fracturing technique where the solids used comprised of roughly 65% natural sand and 35% ceramic proppants. The results show successful placement of the fracturing treatment into the formation. Despite sand crushing, the data show reasonable stimulation results and productivity enhancements. A number of important findings were also realized based on the analysis of the production performance, the reservoir transient pressure data, and the recovered solids and liquids. The discussions shared in this work including analysis of field data yielded important findings and recommendations. Particularly, the concept of applying nonstandard proppants, such as silica sand for hydraulic fracturing treatments is proven feasible. Overall, the new fracturing technique shows considerable potentials for sufficient process optimization and utilization of abundant resources in production operations.

Production metering of a Saudi Arabian rich gas condensate reservoir with an average condensate to gas ratio (CGR) of 330 stock tank barrels/million standard cubic feet (STB/MMscf) is under evaluation. Inapplicability of Venturi meters, due to high liquid production, accompanied by the absence of multiphase flow meters and dedicated permanent test separator facility for individual testing, has resulted in a major metering challenge during the production life of this field. Infrequent deliverability tests with costly portable test separators are the only way to obtain direct and accurate gas and condensate rate measurements, which has severely affected the rate allocation accuracy. In this study, an alternative solution was employed to improve gas rate allocation and target rate compliance. Understanding the nature of multiphase flow through chokes and the principals of flow calculations to derive accurate correlations and models is the only alternative to mitigate the lack of surface metering devices in such a high CGR environment. Choke equations rely heavily on choke parameters, surface measurements, and fluid properties with some assumed empirical constants. The majority of the published choke correlations have their unique empirical constants that fit the flow conditions and fluid properties of the studied fields. In this study, a numerical optimization technique was implemented to develop and brand two empirical choke correlations, which model the gas condensate flow through chokes under critical flow conditions in the subject field. An iterative methodology was performed by capitalizing on a nonlinear algorithm to analyze 64 well test data points, collected from 16 different separator tests, to identify the unique values of the empirical constants, which would yield the most accurate flow rate estimations. Statistical evaluation results indicate the developed empirical choke models yielded encouraging results. The models successfully matched the measured gas flow rates, from 26 well tests, with less than 5% average absolute error, proving the high accuracy of these models in estimating the flow rates. In addition, back allocation task was greatly simplified by utilizing these developed choke equations. Comparison between the total field choke equation estimated rate and measured field gas rate at the gas plant for a period of 3 months showed an outstanding agreement with less than 5% average error and 1.02 average allocation factor. Moreover, the investigated empirical constants were examined in a different field with similar fluid properties and obtained excellent matching outcomes as well, reconfirming the precision of these correlations in estimating the gas rates in a high CGR environment. The applications of these correlations will allow field operators to accurately estimate the flow rates without the necessity of conducting frequent costly separator tests, or installing expensive permanent multiphase flow meters.

Sand production is one of the major issues in unconsolidated sandstone gas and oil reservoirs. The amount of the produced sand in gas wells might vary from a few grams to a few kilograms per hour, yet it can lead to the erosion of downhole and surface equipment and to partial or complete filling of the perforations, the screens or gravel pack completions downhole, hence localizing and quantifying the amount of sand downhole is a necessity for sand production management and sand shut-off, and to update accurately the existing geomechanical models to save huge costs involved from the CT clean-out operations and the repairs caused by erosion. A newly developed downhole sand production measurement was successfully tested. The tool incorporates an innovative design that enables enhanced sensitivity to minute sand entries within the wellbore with minimal interference from the logging environment. This novel measurement was trial tested in different well completions. The carefully designed logging programs involved combining production logging tools – either conventional or array logging tools – along with the downhole sand detection tool for comprehensive log data interpretation. In this paper we illustrate with examples the results of the trial test and pinpoint the advantages as well as limitations of this new technology. Log results in the vertical gas well were generally superior to those from other wells. Where the tool illustrated high sensitivity to locating small grains of sand production across the perforated intervals, as well as providing representative qualitative assessment of downhole sand production volume. Yet, most importantly it helped obtain the optimum drawdown for the free sand rate in this well. The tool was deployed also in one deviated oil well and two horizontal gas wells. These wells are completed with smart completions, sand screens and frac ports. The results helped reveal the efficiency of the screens and the integrity issues of frac ports and determine future plan to patch the frac ports to shut-off sand production. It is generally observed that log data quality and interpretation were challenged by the downhole logging environment and the well condition during log data acquisition. The new downhole sand detection technology shows added value to allocate and qualitatively quantify sand production, check the integrity of sand screens and gravel packs, and several other applications. Candidate selection, job design and real-time log monitoring are crucial for the optimum benefit of the logging survey.

Tight Gas reservoirs require fracturing as part of the reservoir exploitation strategy. The quality of perforations play an important role in establishing effective contact with the reservoir prior to fracturing. Several perforating technologies have been used and evaluated to optimize operations and saving completion costs. This practice has provided a wealth of data to analyze the most efficient strategy for tight gas reservoirs. An optimized perforating method has been implemented recently in fields that traditionally required hydraulic fracturing to bypass drilling damage and produce commercially. Combining deep penetration charges with an instantaneous underbalance is the key ingredient for this method. The method results in achieving maximum reservoir contact, away from washouts, breakouts and damaged zone; thereby, delivering clean perforation tunnels and higher entrance hole diameter. In cases, where the productivity is limited by extremely low permeability and hydraulic fracturing becomes inevitable, the benefits extend to the fracturing operation in terms of lowering the breakdown and treatment pressures, improved treatment rates, effective proppant placement and minimizing the likelihood of pre-mature screen out. The paper outlines the detailed workflow including candidate recognition, treatment design, execution and evaluation leading to significant savings in operating expenditure. The paper also provides a comprehensive comparison with other perforating practices and evaluate their effectiveness. The results obtained through deployment of this method on several wells are extremely encouraging. The wells were able to produce naturally, exceeding production expectations. As a result, significant time and cost savings were realized by eliminating subsequent production operations and well intervention work. The pressure transient analysis showed low skin pointing towards insignificant near wellbore damage. This innovative method improves the way perforations are performed. Encouraged by this success, additional candidates are being evaluated with similar approach with an objective to optimize completion costs and improving initial production.